EP3257570A1 - Integrated desulfurization and carbon dioxide capture system for flue gases - Google Patents
Integrated desulfurization and carbon dioxide capture system for flue gases Download PDFInfo
- Publication number
- EP3257570A1 EP3257570A1 EP17173328.0A EP17173328A EP3257570A1 EP 3257570 A1 EP3257570 A1 EP 3257570A1 EP 17173328 A EP17173328 A EP 17173328A EP 3257570 A1 EP3257570 A1 EP 3257570A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- flue gas
- metal
- gas stream
- salt
- carbon dioxide
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 title claims abstract description 164
- 239000003546 flue gas Substances 0.000 title claims abstract description 158
- 238000006477 desulfuration reaction Methods 0.000 title claims abstract description 111
- 230000023556 desulfurization Effects 0.000 title claims abstract description 111
- 229910002092 carbon dioxide Inorganic materials 0.000 title claims abstract description 88
- 239000001569 carbon dioxide Substances 0.000 title claims abstract description 87
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims abstract description 152
- 229910052815 sulfur oxide Inorganic materials 0.000 claims abstract description 73
- XTQHKBHJIVJGKJ-UHFFFAOYSA-N sulfur monoxide Chemical class S=O XTQHKBHJIVJGKJ-UHFFFAOYSA-N 0.000 claims abstract description 49
- 239000012530 fluid Substances 0.000 claims abstract description 9
- 238000004891 communication Methods 0.000 claims abstract description 8
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 claims description 184
- 229910021529 ammonia Inorganic materials 0.000 claims description 90
- 238000000034 method Methods 0.000 claims description 79
- 229910052751 metal Inorganic materials 0.000 claims description 53
- 239000002184 metal Substances 0.000 claims description 53
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 claims description 44
- 238000001816 cooling Methods 0.000 claims description 40
- BFNBIHQBYMNNAN-UHFFFAOYSA-N ammonium sulfate Chemical compound N.N.OS(O)(=O)=O BFNBIHQBYMNNAN-UHFFFAOYSA-N 0.000 claims description 36
- 229910052921 ammonium sulfate Inorganic materials 0.000 claims description 34
- 235000011130 ammonium sulphate Nutrition 0.000 claims description 32
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 claims description 30
- 238000000909 electrodialysis Methods 0.000 claims description 28
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 27
- 239000006096 absorbing agent Substances 0.000 claims description 26
- BVKZGUZCCUSVTD-UHFFFAOYSA-N carbonic acid Chemical class OC(O)=O BVKZGUZCCUSVTD-UHFFFAOYSA-N 0.000 claims description 26
- 239000012528 membrane Substances 0.000 claims description 25
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 24
- 229910052799 carbon Inorganic materials 0.000 claims description 24
- 239000001099 ammonium carbonate Substances 0.000 claims description 23
- ATRRKUHOCOJYRX-UHFFFAOYSA-N Ammonium bicarbonate Chemical group [NH4+].OC([O-])=O ATRRKUHOCOJYRX-UHFFFAOYSA-N 0.000 claims description 22
- 235000012538 ammonium bicarbonate Nutrition 0.000 claims description 18
- 229910000013 Ammonium bicarbonate Inorganic materials 0.000 claims description 17
- 229910000000 metal hydroxide Inorganic materials 0.000 claims description 17
- 150000004692 metal hydroxides Chemical class 0.000 claims description 17
- 235000008733 Citrus aurantifolia Nutrition 0.000 claims description 16
- 235000011941 Tilia x europaea Nutrition 0.000 claims description 16
- 239000004571 lime Substances 0.000 claims description 16
- 150000003467 sulfuric acid derivatives Chemical class 0.000 claims description 16
- 150000005323 carbonate salts Chemical class 0.000 claims description 15
- 238000002485 combustion reaction Methods 0.000 claims description 15
- 229910044991 metal oxide Inorganic materials 0.000 claims description 13
- 150000004706 metal oxides Chemical class 0.000 claims description 13
- 235000017557 sodium bicarbonate Nutrition 0.000 claims description 13
- 229910000030 sodium bicarbonate Inorganic materials 0.000 claims description 13
- 229910052784 alkaline earth metal Inorganic materials 0.000 claims description 12
- 150000003839 salts Chemical class 0.000 claims description 12
- 235000019738 Limestone Nutrition 0.000 claims description 11
- 239000006028 limestone Substances 0.000 claims description 11
- 238000011144 upstream manufacturing Methods 0.000 claims description 10
- 150000001342 alkaline earth metals Chemical class 0.000 claims description 9
- 235000011121 sodium hydroxide Nutrition 0.000 claims description 9
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 claims description 8
- 229910052783 alkali metal Inorganic materials 0.000 claims description 8
- 150000001340 alkali metals Chemical class 0.000 claims description 8
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 claims description 7
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 claims description 5
- 238000010438 heat treatment Methods 0.000 claims description 5
- UIIMBOGNXHQVGW-DEQYMQKBSA-M Sodium bicarbonate-14C Chemical compound [Na+].O[14C]([O-])=O UIIMBOGNXHQVGW-DEQYMQKBSA-M 0.000 claims description 4
- 229910000029 sodium carbonate Inorganic materials 0.000 claims description 4
- 235000017550 sodium carbonate Nutrition 0.000 claims description 4
- 239000003344 environmental pollutant Substances 0.000 abstract description 3
- 231100000719 pollutant Toxicity 0.000 abstract description 3
- 239000000047 product Substances 0.000 description 33
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 33
- 229910001868 water Inorganic materials 0.000 description 31
- 239000000243 solution Substances 0.000 description 29
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 28
- 239000007789 gas Substances 0.000 description 24
- PMZURENOXWZQFD-UHFFFAOYSA-L Sodium Sulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=O PMZURENOXWZQFD-UHFFFAOYSA-L 0.000 description 19
- 229910052938 sodium sulfate Inorganic materials 0.000 description 18
- 238000006243 chemical reaction Methods 0.000 description 16
- 235000011152 sodium sulphate Nutrition 0.000 description 15
- 239000002250 absorbent Substances 0.000 description 12
- 230000002745 absorbent Effects 0.000 description 12
- 239000002002 slurry Substances 0.000 description 11
- 239000003153 chemical reaction reagent Substances 0.000 description 10
- 239000003513 alkali Substances 0.000 description 9
- 239000007787 solid Substances 0.000 description 9
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonium chloride Substances [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 7
- VHUUQVKOLVNVRT-UHFFFAOYSA-N Ammonium hydroxide Chemical compound [NH4+].[OH-] VHUUQVKOLVNVRT-UHFFFAOYSA-N 0.000 description 7
- 229910001854 alkali hydroxide Inorganic materials 0.000 description 7
- 229910001860 alkaline earth metal hydroxide Inorganic materials 0.000 description 7
- 235000011114 ammonium hydroxide Nutrition 0.000 description 7
- 239000010440 gypsum Substances 0.000 description 7
- 229910052602 gypsum Inorganic materials 0.000 description 7
- 239000007788 liquid Substances 0.000 description 7
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 6
- 238000010521 absorption reaction Methods 0.000 description 6
- 230000002378 acidificating effect Effects 0.000 description 6
- 239000011734 sodium Substances 0.000 description 6
- 229910052708 sodium Inorganic materials 0.000 description 6
- 235000012501 ammonium carbonate Nutrition 0.000 description 5
- AXCZMVOFGPJBDE-UHFFFAOYSA-L calcium dihydroxide Chemical compound [OH-].[OH-].[Ca+2] AXCZMVOFGPJBDE-UHFFFAOYSA-L 0.000 description 5
- MWUXSHHQAYIFBG-UHFFFAOYSA-N nitrogen oxide Inorganic materials O=[N] MWUXSHHQAYIFBG-UHFFFAOYSA-N 0.000 description 5
- 239000003570 air Substances 0.000 description 4
- 239000000920 calcium hydroxide Substances 0.000 description 4
- 229910001861 calcium hydroxide Inorganic materials 0.000 description 4
- ODINCKMPIJJUCX-UHFFFAOYSA-N calcium oxide Inorganic materials [Ca]=O ODINCKMPIJJUCX-UHFFFAOYSA-N 0.000 description 4
- 239000000356 contaminant Substances 0.000 description 4
- 229910000069 nitrogen hydride Inorganic materials 0.000 description 4
- 239000007832 Na2SO4 Substances 0.000 description 3
- 239000002253 acid Substances 0.000 description 3
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 239000000292 calcium oxide Substances 0.000 description 3
- 235000012255 calcium oxide Nutrition 0.000 description 3
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 3
- GBAOBIBJACZTNA-UHFFFAOYSA-L calcium sulfite Chemical compound [Ca+2].[O-]S([O-])=O GBAOBIBJACZTNA-UHFFFAOYSA-L 0.000 description 3
- 235000010261 calcium sulphite Nutrition 0.000 description 3
- 238000009833 condensation Methods 0.000 description 3
- 230000005494 condensation Effects 0.000 description 3
- VTHJTEIRLNZDEV-UHFFFAOYSA-L magnesium dihydroxide Chemical compound [OH-].[OH-].[Mg+2] VTHJTEIRLNZDEV-UHFFFAOYSA-L 0.000 description 3
- 239000000347 magnesium hydroxide Substances 0.000 description 3
- 229910001862 magnesium hydroxide Inorganic materials 0.000 description 3
- 239000001301 oxygen Substances 0.000 description 3
- 229910052760 oxygen Inorganic materials 0.000 description 3
- 238000012856 packing Methods 0.000 description 3
- 239000013618 particulate matter Substances 0.000 description 3
- 238000010926 purge Methods 0.000 description 3
- 229920006395 saturated elastomer Polymers 0.000 description 3
- 239000007921 spray Substances 0.000 description 3
- 238000005200 wet scrubbing Methods 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 2
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 2
- CSNNHWWHGAXBCP-UHFFFAOYSA-L Magnesium sulfate Chemical compound [Mg+2].[O-][S+2]([O-])([O-])[O-] CSNNHWWHGAXBCP-UHFFFAOYSA-L 0.000 description 2
- LSNNMFCWUKXFEE-UHFFFAOYSA-N Sulfurous acid Chemical class OS(O)=O LSNNMFCWUKXFEE-UHFFFAOYSA-N 0.000 description 2
- 239000012080 ambient air Substances 0.000 description 2
- BVCZEBOGSOYJJT-UHFFFAOYSA-N ammonium carbamate Chemical compound [NH4+].NC([O-])=O BVCZEBOGSOYJJT-UHFFFAOYSA-N 0.000 description 2
- ZEYWAHILTZGZBH-UHFFFAOYSA-N azane;carbon dioxide Chemical compound N.O=C=O ZEYWAHILTZGZBH-UHFFFAOYSA-N 0.000 description 2
- 239000006227 byproduct Substances 0.000 description 2
- 235000011116 calcium hydroxide Nutrition 0.000 description 2
- BRPQOXSCLDDYGP-UHFFFAOYSA-N calcium oxide Chemical compound [O-2].[Ca+2] BRPQOXSCLDDYGP-UHFFFAOYSA-N 0.000 description 2
- PASHVRUKOFIRIK-UHFFFAOYSA-L calcium sulfate dihydrate Chemical compound O.O.[Ca+2].[O-]S([O-])(=O)=O PASHVRUKOFIRIK-UHFFFAOYSA-L 0.000 description 2
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 2
- KXDHJXZQYSOELW-UHFFFAOYSA-N carbonic acid monoamide Natural products NC(O)=O KXDHJXZQYSOELW-UHFFFAOYSA-N 0.000 description 2
- 238000005341 cation exchange Methods 0.000 description 2
- 239000007795 chemical reaction product Substances 0.000 description 2
- 239000003245 coal Substances 0.000 description 2
- 239000000498 cooling water Substances 0.000 description 2
- 238000000354 decomposition reaction Methods 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- TXKMVPPZCYKFAC-UHFFFAOYSA-N disulfur monoxide Inorganic materials O=S=S TXKMVPPZCYKFAC-UHFFFAOYSA-N 0.000 description 2
- 239000001257 hydrogen Substances 0.000 description 2
- 229910052739 hydrogen Inorganic materials 0.000 description 2
- 150000004679 hydroxides Chemical class 0.000 description 2
- -1 hydroxyl ions Chemical class 0.000 description 2
- 230000010354 integration Effects 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 150000002739 metals Chemical class 0.000 description 2
- 238000010248 power generation Methods 0.000 description 2
- 239000002243 precursor Substances 0.000 description 2
- 239000012266 salt solution Substances 0.000 description 2
- UBXAKNTVXQMEAG-UHFFFAOYSA-L strontium sulfate Chemical compound [Sr+2].[O-]S([O-])(=O)=O UBXAKNTVXQMEAG-UHFFFAOYSA-L 0.000 description 2
- LSNNMFCWUKXFEE-UHFFFAOYSA-L sulfite Chemical compound [O-]S([O-])=O LSNNMFCWUKXFEE-UHFFFAOYSA-L 0.000 description 2
- 231100000331 toxic Toxicity 0.000 description 2
- 230000002588 toxic effect Effects 0.000 description 2
- QGZKDVFQNNGYKY-UHFFFAOYSA-O Ammonium Chemical class [NH4+] QGZKDVFQNNGYKY-UHFFFAOYSA-O 0.000 description 1
- 239000002028 Biomass Substances 0.000 description 1
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 1
- KXDHJXZQYSOELW-UHFFFAOYSA-M Carbamate Chemical compound NC([O-])=O KXDHJXZQYSOELW-UHFFFAOYSA-M 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- KRHYYFGTRYWZRS-UHFFFAOYSA-N Fluorane Chemical compound F KRHYYFGTRYWZRS-UHFFFAOYSA-N 0.000 description 1
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 1
- CBENFWSGALASAD-UHFFFAOYSA-N Ozone Chemical compound [O-][O+]=O CBENFWSGALASAD-UHFFFAOYSA-N 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 238000003916 acid precipitation Methods 0.000 description 1
- 239000000809 air pollutant Substances 0.000 description 1
- 231100001243 air pollutant Toxicity 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 229910052925 anhydrite Inorganic materials 0.000 description 1
- 238000005349 anion exchange Methods 0.000 description 1
- 239000003011 anion exchange membrane Substances 0.000 description 1
- 150000001450 anions Chemical class 0.000 description 1
- 239000011575 calcium Substances 0.000 description 1
- 229910052791 calcium Inorganic materials 0.000 description 1
- 229910000019 calcium carbonate Inorganic materials 0.000 description 1
- 235000010216 calcium carbonate Nutrition 0.000 description 1
- 235000011132 calcium sulphate Nutrition 0.000 description 1
- 239000000567 combustion gas Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 238000007599 discharging Methods 0.000 description 1
- 230000005684 electric field Effects 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 238000003912 environmental pollution Methods 0.000 description 1
- 239000010881 fly ash Substances 0.000 description 1
- 239000000446 fuel Substances 0.000 description 1
- 239000005431 greenhouse gas Substances 0.000 description 1
- 239000003673 groundwater Substances 0.000 description 1
- 231100001261 hazardous Toxicity 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 229910000041 hydrogen chloride Inorganic materials 0.000 description 1
- IXCSERBJSXMMFS-UHFFFAOYSA-N hydrogen chloride Substances Cl.Cl IXCSERBJSXMMFS-UHFFFAOYSA-N 0.000 description 1
- 229910000040 hydrogen fluoride Inorganic materials 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 1
- BDAGIHXWWSANSR-NJFSPNSNSA-N hydroxyformaldehyde Chemical compound O[14CH]=O BDAGIHXWWSANSR-NJFSPNSNSA-N 0.000 description 1
- 229910010272 inorganic material Inorganic materials 0.000 description 1
- 239000011147 inorganic material Substances 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 150000002500 ions Chemical class 0.000 description 1
- ZLNQQNXFFQJAID-UHFFFAOYSA-L magnesium carbonate Chemical compound [Mg+2].[O-]C([O-])=O ZLNQQNXFFQJAID-UHFFFAOYSA-L 0.000 description 1
- 239000001095 magnesium carbonate Substances 0.000 description 1
- 229910000021 magnesium carbonate Inorganic materials 0.000 description 1
- 235000014380 magnesium carbonate Nutrition 0.000 description 1
- 229910052943 magnesium sulfate Inorganic materials 0.000 description 1
- 235000019341 magnesium sulphate Nutrition 0.000 description 1
- JESHZQPNPCJVNG-UHFFFAOYSA-L magnesium;sulfite Chemical compound [Mg+2].[O-]S([O-])=O JESHZQPNPCJVNG-UHFFFAOYSA-L 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- VUZPPFZMUPKLLV-UHFFFAOYSA-N methane;hydrate Chemical compound C.O VUZPPFZMUPKLLV-UHFFFAOYSA-N 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 238000007254 oxidation reaction Methods 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 125000005575 polycyclic aromatic hydrocarbon group Chemical group 0.000 description 1
- 235000015497 potassium bicarbonate Nutrition 0.000 description 1
- 239000011736 potassium bicarbonate Substances 0.000 description 1
- 229910000028 potassium bicarbonate Inorganic materials 0.000 description 1
- TYJJADVDDVDEDZ-UHFFFAOYSA-M potassium hydrogencarbonate Chemical compound [K+].OC([O-])=O TYJJADVDDVDEDZ-UHFFFAOYSA-M 0.000 description 1
- OTYBMLCTZGSZBG-UHFFFAOYSA-L potassium sulfate Chemical compound [K+].[K+].[O-]S([O-])(=O)=O OTYBMLCTZGSZBG-UHFFFAOYSA-L 0.000 description 1
- 229910052939 potassium sulfate Inorganic materials 0.000 description 1
- 235000011151 potassium sulphates Nutrition 0.000 description 1
- 230000008929 regeneration Effects 0.000 description 1
- 238000011069 regeneration method Methods 0.000 description 1
- 238000009420 retrofitting Methods 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- 239000002910 solid waste Substances 0.000 description 1
- 239000002594 sorbent Substances 0.000 description 1
- 229910000018 strontium carbonate Inorganic materials 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 239000011593 sulfur Substances 0.000 description 1
- AKEJUJNQAAGONA-UHFFFAOYSA-N sulfur trioxide Inorganic materials O=S(=O)=O AKEJUJNQAAGONA-UHFFFAOYSA-N 0.000 description 1
- 239000002352 surface water Substances 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
Images
Classifications
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/75—Multi-step processes
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- B—PERFORMING OPERATIONS; TRANSPORTING
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- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/50—Sulfur oxides
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/50—Sulfur oxides
- B01D53/501—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound
- B01D53/505—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound in a spray drying process
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/62—Carbon oxides
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/96—Regeneration, reactivation or recycling of reactants
- B01D53/965—Regeneration, reactivation or recycling of reactants including an electrochemical process step
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
- B01D61/42—Electrodialysis; Electro-osmosis ; Electro-ultrafiltration; Membrane capacitive deionization
- B01D61/422—Electrodialysis
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/30—Alkali metal compounds
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/40—Alkaline earth metal or magnesium compounds
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
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- B01D2251/60—Inorganic bases or salts
- B01D2251/606—Carbonates
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/10—Inorganic absorbents
- B01D2252/102—Ammonia
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/50—Carbon oxides
- B01D2257/504—Carbon dioxide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2258/00—Sources of waste gases
- B01D2258/02—Other waste gases
- B01D2258/0283—Flue gases
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/50—Sulfur oxides
- B01D53/508—Sulfur oxides by treating the gases with solids
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
- Y02A50/00—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE in human health protection, e.g. against extreme weather
- Y02A50/20—Air quality improvement or preservation, e.g. vehicle emission control or emission reduction by using catalytic converters
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
Definitions
- This disclosure generally relates to an integrated desulfurization and carbon dioxide capture system.
- this disclosure generally relates to an integrated desulfurization and carbon dioxide capture for flue gases.
- Power generation systems e.g., coal-fired and oil fired power plants
- hydrocarbon based fuels in order to generate energy.
- Such systems generally produce an end product that comprises primarily carbon dioxide and water (e.g., steam) as by-products of the energy generation process.
- the end products will also include varying amounts of nitrogen, oxygen, sulfur dioxide and other compounds.
- Power plants emit air pollutants that may be toxic, e. g., toxic metals and polyaromatic hydrocarbons; precursors to acid rain, e.g., sulfur oxides (SO x ) such as sulfur dioxide (SO 2 ) and nitrogen oxides (NO x ); precursors to ozone such as NO 2 and reactive organic gases; particulate matter; and greenhouse gases, notably carbon dioxide (CO 2 ).
- SO x sulfur oxides
- NO x nitrogen oxides
- ozone such as NO 2 and reactive organic gases
- particulate matter notably carbon dioxide (CO 2 ).
- Power plants also discharge potentially harmful effluents into surface and ground water, and generate considerable amounts of solid wastes, some of which may be hazardous.
- removal of contaminants involves equipment and processes to remove sulfur-type pollutants (e.g., flue gas desulfurization) and then separate equipment and processes are used to remove and capture the carbon dioxide-type pollutants.
- sulfur-type pollutants e.g., flue gas desulfurization
- Carbon dioxide capture systems include pre-combustion (e.g., oxy-combustion) or post-combustion systems (e.g., chilled ammonia process (CAP) and advanced amines process (AAP)).
- pre-combustion e.g., oxy-combustion
- post-combustion systems e.g., chilled ammonia process (CAP) and advanced amines process (AAP)
- CAP chilled ammonia process
- AAP advanced amines process
- Post-combustion carbon dioxide capture can be applied to various types of power plants such as coal, gas and biomass fired ones, as well as a vast range of industrial processes emitting carbon dioxide.
- Post combustion carbon dioxide capture technology generally includes a chemical absorption process. The following discussion includes the chilled ammonia process.
- Sulfur dioxide is an acid gas, and, therefore, the typical sorbent slurries or other materials used to remove the SO 2 from the flue gases are alkaline.
- Sulfur dioxide capture systems include the use of flue gas desulfurization units. Flue gas desulfurization systems include either wet flue gas desulfurization system (Wet FGD) or dry flue gas desulfurization systems (Dry FGD). In wet FGD, flue gas is reacted with a reagent under saturated conditions. In dry FGD the flue gas is reacted with a reagent at a temperature 30-50 degrees F above adiabatic saturation.
- Wet FGD wet flue gas desulfurization system
- Dry FGD dry flue gas desulfurization systems
- the reaction taking place in wet scrubbing using a CaCO 3 (limestone) slurry produces CaSO 3 (calcium sulfite) and can be expressed as: CaCO 3 (solid) + SO 2 (gas) ⁇ CaSO 3 (solid) + CO 2 (gas)
- the reaction also produces CaSO 3 (calcium sulfite) and can be expressed as: Ca(OH) 2 (solid) + SO 2 (gas) ⁇ CaSO 3 (solid) + H 2 O (liquid)
- Mg(OH) 2 (magnesium hydroxide) slurry the reaction produces MgSO 3 (magnesium sulfite) and can be expressed as: Mg(OH) 2 (solid) + SO 2 (gas) ⁇ MgSO 3 (solid) + H 2 O (liquid)
- the CaSO 3 (calcium sulfite) can be expressed as: Mg(OH) 2 (solid) + SO 2 (gas) ⁇ MgSO 3 (solid) + H 2 O (liquid)
- lime is a calcium-containing inorganic material in which carbonates, oxides and hydroxides predominate and may be used in lieu of sodium carbonate.
- Wet lime or limestone based processes also represent a popular way to capture CO 2 , SO x , and other acidic gases.
- the capital cost of a sodium based system is significantly lower than the lime/limestone based system.
- the cost of the sodium based reagents are much higher than the lime or limestone reagents and hence sodium based desulfurization system has found less attention than its counterpart lime/limestone based desulfurization processes.
- sodium reagents are used for the utilization for SOx re-capture and recycle of ammonia for CO 2 capture and also, sulfuric acid for ammonia capture. This significantly reduces the operating cost of the process.
- an integrated system for capturing carbon dioxide and sulfur oxides from a flue gas stream comprising a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; where the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt is used to absorb sulfur oxides from the flue gas stream to form a metal sulfate; and a carbon capture system in fluid communication with the desulfurization chamber; where the carbon capture system is operative to absorb carbon dioxide from the flue gas stream.
- a method comprising charging a flue gas stream produced in a combustion process to an integrated system for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system comprises a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; and a carbon capture system in fluid communication with the desulfurization chamber; absorbing sulfur oxides from the flue gas stream in the desulfurization chamber; and absorbing carbon dioxide from the flue gas stream in the carbon capture system.
- the method comprises discharging a flue gas from a combustion process (such as from a coal combustion furnace) to a desulfurization chamber where sulfur oxides (SO x ) is removed in the form of a sulfate salt.
- the flue gases now devoid of the sulfur oxides are then discharged to a carbon capture system where the carbon dioxide present in the flue gas stream is removed in the form of a carbonate salt and/or a bicarbonate salt.
- the carbonate salt and/or the bicarbonate salt is then decomposed to release carbon dioxide.
- the carbon dioxide is eventually sequestered while the flue gas now devoid of carbon dioxide and sulfur oxides (SO x ) is released to the atmosphere via a stack.
- Figure 1 represents an exemplary diagram that depicts a chilled ammonia carbon dioxide capture system 10 for the removal of carbon dioxide from a flue gas stream. It should be noted that the process shown in Figure 1 is only a high level overview of the Chilled Ammonia Process (CAP) and not all details associated with the CAP process are shown.
- CAP Chilled Ammonia Process
- the system 10 comprises a direct contact cooling vessel (DCC) 4, a direct contact heating vessel (DCH) 6, a water wash station 8, an absorber 12 and a regenerator 14.
- DCC direct contact cooling vessel
- DCH direct contact heating vessel
- a flue gas stream containing carbon dioxide that emanates from a combustion process is charged to a direct contact cooling vessel 4 prior to being charged to the absorber 12.
- the direct contact cooling vessel 4 reduces temperature of the incoming flue gas stream and removes residual acidic gases such as SOx and particulate matter.
- the flue gas stream is then charged to the absorber 12 where carbon dioxide is removed using an absorbent solution (also referred to herein as an ammoniated solution or an ammoniated slurry).
- an absorbent solution also referred to herein as an ammoniated solution or an ammoniated slurry.
- the absorption of the acidic components such as carbon dioxide present in the flue gas stream is achieved when the absorber 12 is operated at a low temperature, for example, between zero and thirty degrees Celsius (0 to 30°C).
- absorption of the acidic component from flue gas stream is achieved when the absorber is operated at a temperature between zero and ten degrees Celsius (0 to 10°C). By operating at relatively low temperatures, ammonia loss within the system 10 is minimized.
- the ammonia reacts with the carbon dioxide present in the flue gas to form ammonium carbonate, ammonium bicarbonate, ammonium carbamate (also referred to as a carbon dioxide rich ammonia solution).
- the carbon dioxide rich ammonia solution is charged to the regenerator 14 where it is heated to release the carbon dioxide thereby resulting in a carbon dioxide lean ammonia solution.
- the carbon dioxide is subsequently cleaned and sequestered or stored for further utilization.
- the carbon dioxide lean ammonia solution is recycled back to the absorber 12, where it recaptures additional carbon dioxide in a sequential portion of the flue gas stream.
- the flue gas stream from a boiler enters the direct contact cooling vessel 4 to have its temperature reduced and to have residual acidic gases removed from it.
- the direct contact cooling vessel 4 uses ambient air or cooling water to lower the recirculation liquid temperature. Flue gas enters the direct contact cooling vessel 4 inlet at the bottom and flows upward through the packing (not shown). Cool water is sprayed at the top of the packing and flows downward, counter to the flue gas flow. As the gas flows upward through direct contact cooling vessel 4, it is forced into contact with the water. Direct cooling of the saturated flue gas results in the condensation of most of the water in the flue gas stream.
- the residual acidic gases e.g., SO 2 , SO 3 , SO x , hydrogen chloride, and hydrogen fluoride gas
- the sulfur dioxide (SO 2 ) is captured by the ammonia to produce ammonium sulfate.
- the flue gases leave the direct contact cooling vessel 4 and are charged to the absorber 12.
- the absorber 12 employs an absorbent solution (disposed therein) or a slurry that facilitates the absorption and the removal of a gaseous component such as carbon dioxide from the flue gas stream.
- the absorbent solution used in the absorber is a solution or slurry including ammonia (referred to above as an ammoniated solution or slurry).
- the ammonia can be in the form of an ammonium ion (NH 4 + ), ammonium carbamate, ammonium bicarbonate, or in the form of dissolved molecular ammonia (NH 3 ).
- the absorbent solution or slurry may be comprised of ammonium carbonate, carbamate and bicarbonate ions.
- the flue gas flows upwards through the absorber 12, it is contacted with the scrubbing slurry solution containing dissolved ammonium carbonate and ammonium bicarbonate suspended solids that flow in a countercurrent direction to the flue gas, and the CO 2 is absorbed.
- the flue gas exits the water wash column and enters the direct contact heating vessel 6 for removal of residual ammonia where it is captured by sulfuric acid to form ammonium sulfate before entering the chimney as clean combustion gas.
- the flue gas exits the carbon dioxide absorber 12 and enters a water wash station 8 to reduce the ammonia vapor from the flue gas. In the water wash station 8, ammonia is removed using chilled water..
- the water wash station 8 is a packed column that utilizes water to absorb ammonia from the flue gas.
- the temperature of the flue gas is maintained using heat exchangers and a mechanical chilling system.
- the ammoniated water is sent to a stripper column (not shown) (CO 2 /NH 3 stripper) where the ammonia is stripped and returned to the process as reagent.
- the clean water from the CO 2 /NH 3 stripper is re-used within the water wash column to remove additional ammonia. Energy for the CO 2 /NH 3 stripping column is provided by steam from the power generation facility.
- the ammoniated solution or ammoniated slurry (now rich in carbon dioxide in the form of ammonium carbonate or ammonium bicarbonate) is charged to a regenerator 14 where it is heated to decompose it thereby producing carbon dioxide and the absorbent solution.
- the absorbent solution is returned to the absorber 12 to contact additional flue gas and to absorb carbon dioxide from it.
- the remainder of the flue gas stream (now substantially devoid of carbon dioxide) is then charged to a water wash station 8 to remove ammonia from it.
- the regenerator 14 is a stripper column that contains a mass transfer process.
- the feed to the regenerator 14 is introduced at several stages.
- the carbon dioxide rich ammonia solution is flashed by heat introduced in the regenerator reboiler. Flashed carbon dioxide in the feed proceeds up the column to the overhead.
- the rich solution falls through the lower regenerator bed, carbon dioxide is separated and rises to the regenerator overhead, and the solution becomes leaner as it reaches the bottom of the column.
- the lean solution is then returned to the absorber 12 for re-use.
- the integrated system comprises a desulfurization system that may comprise either a wet flue gas desulfurization (WFGD) system and/or a dry flue gas desulfurization system (DFGD) to remove sulfur oxides (SO x ) and a carbon capture system (CCS) that captures carbon dioxide from the flue gas stream.
- the desulfurization system comprises a desulfurization chamber where a carbonate or bicarbonate salt is used to capture SO x from the flue gas stream and gets converted to a sulfate salt in the process.
- the flue gas stream now substantially devoid of sulfur oxides is charged to the carbon capture system where the carbon dioxides are captured.
- Figures 2 - 4 depict embodiments of integrated systems 100 that may be used for removing both sulfur oxides and carbon dioxide from a flue gas stream.
- the systems of Figures 2 - 4 employ a number of common processes, as described herein.
- Air-Preheater 102, Bag-house 104 and Spray Drier 114 Air-Preheater 102, Bag-house 104 and Spray Drier 114:
- Flue gas from a combustion process is discharged to an air-preheater 102 that is in fluid communication with a desulfurization chamber 116 via a bag-house 104.
- the bag-house 104 facilitates the removal of particulate matter (e.g., fly ash particles and the like) prior to the flue gases entering the desulfurization chamber 106.
- particulate matter e.g., fly ash particles and the like
- a spray drier 114 disposed in parallel with the air-preheater 102 is used to dry a small amount of purge material taken out of the desulfurization chamber 106 as a part of zero liquid discharge from the process.
- the desulfurization chamber 106 may be a wet gas desulfurization chamber or a dry gas desulfurization chamber.
- a variety of different salts may be used in the desulfurization chamber 106 to remove sulfur oxides (SOx) from the flue gas stream.
- Preferred salts for use in the desulfurization chamber 106 are carbonates, bicarbonates, oxides and/or hydroxides of metals of Group IA and IIA. These include alkali metals and alkaline earth metals.
- suitable salts for use in the desulfurization chamber are salts such as sodium bicarbonate, potassium bicarbonate, calcium carbonate, calcium oxide, calcium hydroxide, magnesium carbonate, strontium carbonate, and the like.
- a preferred bicarbonate salt for use in the desulfurization chamber 106 is sodium bicarbonate.
- the desulfurization chamber is preferably a wet gas desulfurization chamber.
- the resulting salts produced in the desulfurization chamber 106 as a result of the reaction with the sulfur oxides (SOx from the flue gas stream) are sulfates of alkali metals and alkaline earth metals.
- Exemplary sulfates are sodium sulfate, potassium sulfate, calcium sulfate, magnesium sulfate, strontium sulfate, and the like
- a flue gas stream (from the combustion process) along with a stream of air is introduced into the desulfurization chamber 106.
- the air provides the oxygen that is used to convert the sulfite salt to a sulfate salt.
- a bicarbonate salt is also introduced into the chamber 106 from the product reactor and separator 110.
- the bicarbonate salt reacts with the sulfur oxides present in the flue gas stream to form a sulfate salt.
- the reaction (2) is as follows. 2NaHCO 3 + SO 2 + 1 ⁇ 2O 2 ⁇ Na 2 SO 4 + H 2 O + 2CO 2 (2)
- the sulfate salt (e.g., sodium sulfate) is then charged to the product reactor and separator 110.
- An exemplary salt is sodium sulfate.
- FIG. 1 While the chilled ammonia process comprises a number of different components (such as an absorber, a regenerator, a direct contact cooling vessel, a direct contact heating vessel, a water wash station and a CO 2 wash as shown in the Figure 1 )
- Figures 2 through 4 represent the entire chilled ammonia process by reference numeral 108.
- carbon dioxide is absorbed from the flue gas stream by an absorbent present in an absorber (not shown).
- the absorbent with the carbon dioxide dissolved therein (termed a carbon dioxide-rich solution) is then discharged from the absorber to a regenerator where the carbon dioxide is separated from the absorbent to form a carbon-dioxide-rich stream and a carbon dioxide-lean stream.
- the carbon dioxide-rich stream is then sequestered or utilized.
- the absorbent now devoid of carbon dioxide (termed a carbon dioxide lean ammonia solution) is recycled back to the absorber to absorb additional carbon dioxide from the incoming flue gas stream.
- the product reactor and separator 110 receives ammonium bicarbonate from the chilled ammonia process 108 and reacts it with the sulfate salt to produce ammonium sulfate and the bicarbonate salt.
- This reaction for sodium sulfate is detailed as shown in reaction (1) above and is reproduced again below. Na 2 SO 4 + 2NH 4 HCO 3 ⁇ 2NaHCO 3 + (NH 4 ) 2 SO 4 (1)
- the reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution.
- the sodium bicarbonate is recycled to the desulfurization chamber 106 while the ammonium sulfate is discharged to the bipolar membrane electrodialysis and then decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process.
- ammonia is used as a reagent make-up required in the CO 2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere.
- the bipolar membrane electrodialysis device 112 facilitates the decomposition of ammonium sulfate into sulfuric acid and ammonia.
- the ammonia is charged to the chilled ammonia device 108 and is recycled to the absorber (see Figure 1 ) where it absorbs carbon dioxide to form ammonium carbonate/bicarbonate solution.
- a portion of the sulfuric acid is also charged to the chilled ammonia process 108 where it is used in the DCH () to convert ammonia slip to ammonium sulfate.
- the remaining sulfuric acid may be used for other commercial purposes.
- the ammonium sulfate obtained from the DCC/DCH is fed back to the electrodialysis device 112, where it is decomposed to ammonia and to sulfuric acid in a manner similar to the ammonium sulfate received from the product reactor and separator 110. Any water obtained from the decomposition of ammonium sulfate and any non-decomposed ammonium sulfate produced in the electrodialysis device 112 is returned to the product reactor and separator 110.
- the bipolar membrane electrodialysis device 112 generally includes an anion exchange membrane and a cation exchange membrane physically or chemically bonded together. Under the driving force of an electrical field, the bipolar membrane dissociates water into hydrogen and hydroxyl ions.
- the electrodialysis device eliminates the need for the end user to handle the byproduct stream that would typically be generated using an ammonia solution (i.e., the ammonium sulfate), which will further enhance the efficiency of the chilled ammonia process.
- an ammonia solution i.e., the ammonium sulfate
- Flue gas containing residual SOx is directed from the desulfurization chamber 106 to the direct contact cooling vessel 118.
- the direct contact cooling vessel 118 lies downstream of the desulfurization chamber 116.
- the direct contact cooling vessel 118 lies upstream of the product reactor and separator 110.
- sodium hydroxide solution is charged to the top of the vessel while the flu gas containing residual SOx is charged to the bottom of the reactor.
- the flue gas travels from the bottom upwards counter current to the flow of the sodium hydroxide solution.
- the SOx present in the flue gas stream is absorbed by the sodium hydroxide to form sodium sulfate which is charged to the product reactor and separator 110.
- the flue gas (now devoid of SOx) is charged to the carbon capture system 108.
- Gypsum from the direct contact cooling vessel 118 is fed to the desulfurization chamber 106.
- the product reactor and separator 110 is fed with lime to convert the sodium sulfate to gypsum, which is charged to the wet flue gas desulfurization chamber 106.
- the sodium sulfate produced in direct contact cooling vessel 118 is charged to the product reactor and separator 110 to produce gypsum and sodium hydroxide.
- the gypsum is recycled to the wet flue gas desulfurization chamber 106.
- Sodium hydroxide produced in the product reactor and separator 110 as a result of the reaction between the lime and the sodium sulfate is recycled to the direct contact cooling vessel 118.
- the carbon dioxide obtained from the carbon capture system 108 can then be sequestered or utilized.
- the system of the Figure 2 thus integrates desulfurization of the flue gas stream with carbon dioxide removal.
- the lime and/or limestone present in the wet flue gas desulfurization chamber 106 reacts with the sulfur oxides (SOx) in the flue gas stream to produce gypsum (CaSO 4 .2H 2 O).
- the gypsum may be removed from the flue gas desulfurization chamber 116 and replaced with additional lime and/or limestone to facilitate the further removal of sulfur oxides from the flue gas stream.
- Figure 3 is a depiction of another exemplary integrated system 100 that combines desulfurization with the chilled ammonia process to remove sulfur oxides and carbon dioxide from the flue gas stream.
- a product reactor and separator 110 is used to facilitate the reaction between the sodium sulfate salt (from the desulfurization chamber 106) and ammonium bicarbonate (from the chilled ammonia process 108).
- This reaction is detailed below in (1): Na 2 SO 4 + 2NH 4 HCO 3 ⁇ 2NaHCO 3 + (NH 4 ) 2 SO 4 (1)
- the reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution.
- the sodium bicarbonate is recycled to the desulfurization chamber while the ammonium sulfate is decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process.
- the ammonia is used as a reagent make-up required in the CO 2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere. This is discussed in detail in the sections directed to the product reactor and separator 110 and the desulfurization chamber 106.
- reaction produces a sodium bicarbonate salt and ammonium sulfate solution.
- a sodium bicarbonate salt is precipitated and separated from the mixture and ammonium sulfate solution is sent to a bipolar membrane electrodialysis unit.
- a bipolar membrane electrodialysis unit 112 is used to decompose the ammonium sulfate to ammonia & sulfuric acid which is fed back to the chilled ammonia process. Sulfuric acid is removed from the bipolar membrane electrodialysis unit 112 and a portion of it is fed to the chilled ammonia process.
- the product reactor and separator 110 lies in a cyclical loop with the chilled ammonia process 108 and the desulfurization chamber 106.
- flue gases now devoid of sulfur oxides
- the absorber not shown
- a small portion of the ammonium bicarbonate from the absorber is then discharged from the absorber to the product reactor and separator 110, where it reacts with the sulfate salt to produce a bicarbonate salt, which is charged to the desulfurization chamber 106.
- a number of recycle loops also exist between the product reactor and separator 110, the bipolar membrane electrodialysis unit 112 and the chilled ammonia process 108.
- ammonium sulfate from the product reactor and separator 110 is charged to the bipolar membrane electrodialysis unit 112 while water and unreacted ammonium sulfate are recycled back to the product reactor and separator 110 from the bipolar membrane electrodialysis unit 112.
- Another recycle loop exists between the chilled ammonia process 108 and the bipolar membrane electrodialysis unit 112 where ammonium sulfate from the chilled ammonia process 108 is fed to the bipolar membrane electrodialysis unit 112 and where ammonia and sulfuric acid produced in the bipolar membrane electrodialysis unit 112 are recycled to the chilled ammonia process 108.
- the sodium bicarbonate reacts with sulfur oxides present in the flue gas stream in the desulfurization chamber 106 to produce sodium sulfate.
- the sodium sulfate is charged to the product reactor and separator 110 where a portion of ammonium bicarbonate is received from the absorber (not shown) of the chilled ammonia process 108.
- the reaction between sodium sulfate and ammonium bicarbonate results in the formation of ammonium sulfate and sodium bicarbonate.
- the sodium bicarbonate is recycled to the desulfurization chamber 106 where it reacts with incoming sulfur oxides in the flue gas stream.
- the sodium bicarbonate is thus charged from the product reactor and separator 110 to the desulfurization chamber 106 while sodium sulfate is charged from the desulfurization chamber 106 to product reactor and separator 110.
- the bipolar membrane electrodialysis device 112 receives the ammonium sulfate from the product reactor and separator 110 and decomposes it to ammonia and sulfuric acid.
- the ammonia is charged to the absorber of the chilled ammonia process 108 where it forms ammonium bicarbonate.
- a portion of sulfuric acid generated in the bipolar membrane electrodialysis device 112 is charged to the chilled ammonia process 108 where it reacts with the ammonia slip in the DCH to produce ammonium sulfate.
- This ammonium sulfate is charged to the bipolar membrane electrodialysis device 112 from the chilled ammonia process 108 where it is decomposed to form ammonia and sulfuric acid. Any water or unused ammonium sulfate from the bipolar membrane electrodialysis device 112 are discharged to the product reactor and separator 110.
- a portion of sodium bicarbonate may be diverted from being charged to the desulfurization chamber 106 (from the product reactor and separator 110) to points 101 and 103 upstream and downstream of the air preheater 102 where it can be used to absorb a small portion of sulfur oxides (SOx) from the incoming flue gas stream At points 101 and 103, the temperature of the flue gas stream is higher than when it enters the desulfurization chamber 106 and hence the removal of sulfur oxides (especially SO 3 ) from the flue gas stream is more efficient.
- SOx sulfur oxides
- a small purge stream 105 is charged from the desulfurization chamber 106 to the spray dryer 114 where heat from the flue gas stream is used to dry the contents of the purge stream.
- the Figure 4 depicts another embodiment of the exemplary integrated system 100 that combines sulfur oxide removal with carbon dioxide removal from a flue gas stream once again with the use of the chilled ammonia process.
- the system 100 comprises a wet flue gas desulfurization and/or a dry flue gas desulfurization chamber 116 (hereinafter and a direct contact cooling vessel 118 in addition to the components contained in the system 100 depicted in the Figure 3 ).
- the flue gas desulfurization chamber 106 of the Figure 3 is replaced with a wet flue gas desulfurization chamber 106 that contains lime (CaO or Ca(OH) 2 ) or limestone (CaCO 3 ).
- the wet flue gas desulfurization chamber 106 lies upstream of a direct contact cooling vessel 118.
- the flue gas exiting the flue gas desulfurization unit is typically at a temperature of about 50 to 60°C for wet flue gas desulfurization systems and about 80 to 100°C for dry flue gas desulfurization systems (see the desulfurization chamber 106 of the Figure 3 ).
- the gas is water saturated for systems that employ wet flue gas desulfurization systems whereas for systems with upstream dry flue gas desulfurization, the gas has temperature that is approximately 20 to 40°F above moisture saturation and each gas stream typically contains residual contaminants including SOx, among others.
- DCC direct contact cooling tower vessel
- the direct contact cooling vessel 118 may be a packed tower with liquid recirculation through a cooling tower having multiple stages that uses ambient air to lower the recirculation liquid temperature.
- An alkali and/or alkaline earth metal hydroxide reagent such as sodium hydroxide is introduced into a first stage of the direct contact cooling vessel 118 and mixed with cooling water at a bottom portion of the direct contact cooling vessel 118. Details of the operation of the direct contact cooling vessel 118 are provided in U.S. Patent Publication No. 2013/0064748 , the entire contents of which are hereby incorporated by reference.
- the aqueous alkali and/or alkaline earth metal hydroxide solution is pumped via pump (not shown) through a conduit (not shown) to a top portion of the direct contact cooling vessel 118.
- the aqueous alkali and/or alkaline earth metal hydroxide solution may first be pumped to a chiller (not shown) to further lower the temperature of the aqueous alkali and/or alkaline earth metal hydroxide solution. Flue gas enters the direct contact cooling vessel 118 inlet at the bottom portion and flows upward.
- the cool aqueous alkali and/or alkaline earth metal hydroxide solution is sprayed at the top of the packing and flows downwards, counter to the flue gas flow.
- the flue gas flows upwards through direct contact cooling vessel 118, the flue gas is forced into contact with the aqueous alkali and/or alkaline earth metal hydroxide solution.
- Direct cooling of the saturated flue gas in subsequent stages results in the condensation of most of the water in the flue gas stream.
- the residual gases present in the flue gas are generally rendered water soluble.
- any SOx contaminants entrained in the flue gas react with the aqueous alkali and/or alkaline earth metal hydroxide solution to form a feed-stream of the corresponding aqueous alkali and/or alkaline earth metal sulfur containing salt solution.
- sodium hydroxide when sodium hydroxide is used as the hydroxide solution in the direct contact cooling vessel 118, it absorbs the sulfur oxides to produce sodium sulfate.
- the sodium sulfate from the direct contact cooling vessel 118 is then discharged to the product reactor and separator 110 where it reacts with ammonium bicarbonate to produce ammonium sulfate and sodium bicarbonate as detailed in the Figure 3 above.
- the flue gas stream now substantially devoid of SOx is charged to the chilled ammonia process 108 via stream 107.
- the remainder of the system of the Figure 4 functions as detailed above with reference to the Figure 3 and will not be detailed again in the interests of brevity.
- the system of the Figure 4 is useful in that it is useful for retrofitting existing systems that have carbon capture processes already installed based on Chilled Ammonia process. They are useful where regulations for the desulfurization system are not stringent
- first, second, third, and the like may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another element, component, region, layer or section. Thus, first element, component, region, layer or section discussed below could be termed second element, component, region, layer or section without departing from the teachings of the present invention.
- an upstream device refers to a device producing a fluid output stream that is fed to a “downstream” device.
- the “downstream” device is the device receiving the output from the "upstream” device.
- a device may be both “upstream” and “downstream” of the same device in certain configurations, e.g., a system comprising a recycle loop.
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Abstract
Description
- This disclosure generally relates to an integrated desulfurization and carbon dioxide capture system. In particular, this disclosure generally relates to an integrated desulfurization and carbon dioxide capture for flue gases.
- Power generation systems (e.g., coal-fired and oil fired power plants) generally combust hydrocarbon based fuels in order to generate energy. Such systems generally produce an end product that comprises primarily carbon dioxide and water (e.g., steam) as by-products of the energy generation process. In most cases, the end products will also include varying amounts of nitrogen, oxygen, sulfur dioxide and other compounds.
- Environmental pollution stemming from fossil-fueled power plants is of worldwide concern. Power plants emit air pollutants that may be toxic, e. g., toxic metals and polyaromatic hydrocarbons; precursors to acid rain, e.g., sulfur oxides (SOx) such as sulfur dioxide (SO2) and nitrogen oxides (NOx); precursors to ozone such as NO2 and reactive organic gases; particulate matter; and greenhouse gases, notably carbon dioxide (CO2). Power plants also discharge potentially harmful effluents into surface and ground water, and generate considerable amounts of solid wastes, some of which may be hazardous.
- Generally, removal of contaminants involves equipment and processes to remove sulfur-type pollutants (e.g., flue gas desulfurization) and then separate equipment and processes are used to remove and capture the carbon dioxide-type pollutants.
- Carbon dioxide capture systems include pre-combustion (e.g., oxy-combustion) or post-combustion systems (e.g., chilled ammonia process (CAP) and advanced amines process (AAP)). The post combustion carbon dioxide capture processes are detailed here.
- Post-combustion carbon dioxide capture can be applied to various types of power plants such as coal, gas and biomass fired ones, as well as a vast range of industrial processes emitting carbon dioxide. Post combustion carbon dioxide capture technology generally includes a chemical absorption process. The following discussion includes the chilled ammonia process.
- Sulfur dioxide (SO2) is an acid gas, and, therefore, the typical sorbent slurries or other materials used to remove the SO2 from the flue gases are alkaline. Sulfur dioxide capture systems include the use of flue gas desulfurization units. Flue gas desulfurization systems include either wet flue gas desulfurization system (Wet FGD) or dry flue gas desulfurization systems (Dry FGD). In wet FGD, flue gas is reacted with a reagent under saturated conditions. In dry FGD the flue gas is reacted with a reagent at a temperature 30-50 degrees F above adiabatic saturation.
- The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces CaSO3 (calcium sulfite) and can be expressed as:
CaCO3 (solid) + SO2 (gas) → CaSO3 (solid) + CO2 (gas)
When wet scrubbing with a Ca(OH)2 (lime) slurry, the reaction also produces CaSO3 (calcium sulfite) and can be expressed as:
Ca(OH)2 (solid) + SO2 (gas) → CaSO3 (solid) + H2O (liquid)
When wet scrubbing with a Mg(OH)2 (magnesium hydroxide) slurry, the reaction produces MgSO3 (magnesium sulfite) and can be expressed as:
Mg(OH)2 (solid) + SO2 (gas) → MgSO3 (solid) + H2O (liquid)
To partially offset the cost of the flue gas desulfurization installation, in some designs, the CaSO3 (calcium sulfite) is further oxidized to produce marketable CaSO4.2H2O (gypsum). This technique is also known as forced oxidation:
CaSO3 (solid) + H2O (liquid) + ½O2 (gas) → CaSO4 (solid) + H2O
- Other systems used for capturing SOx use sodium carbonate. Sodium based desulfurization systems are more efficient than the lime or limestone based systems. As seen above, lime is a calcium-containing inorganic material in which carbonates, oxides and hydroxides predominate and may be used in lieu of sodium carbonate. Wet lime or limestone based processes also represent a popular way to capture CO2, SOx, and other acidic gases.
- The capital cost of a sodium based system is significantly lower than the lime/limestone based system. However, the cost of the sodium based reagents are much higher than the lime or limestone reagents and hence sodium based desulfurization system has found less attention than its counterpart lime/limestone based desulfurization processes.
- The use of separate desulfurization systems and carbon dioxide capture systems in a combustion facility is expensive and adds to maintenance costs. It is therefore desirable to reduce costs and improve efficiencies for both the desulfurization process and the carbon capture processes such as chilled ammonia process.
- With this integration of the two systems, sodium reagents are used for the utilization for SOx re-capture and recycle of ammonia for CO2 capture and also, sulfuric acid for ammonia capture. This significantly reduces the operating cost of the process.
- Disclosed herein is an integrated system for capturing carbon dioxide and sulfur oxides from a flue gas stream comprising a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; where the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt is used to absorb sulfur oxides from the flue gas stream to form a metal sulfate; and a carbon capture system in fluid communication with the desulfurization chamber; where the carbon capture system is operative to absorb carbon dioxide from the flue gas stream.
- Disclosed herein too is a method comprising charging a flue gas stream produced in a combustion process to an integrated system for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system comprises a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; and a carbon capture system in fluid communication with the desulfurization chamber; absorbing sulfur oxides from the flue gas stream in the desulfurization chamber; and absorbing carbon dioxide from the flue gas stream in the carbon capture system.
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Figure 1 represents an exemplary diagram that depicts a chilled ammonia carbon dioxide capture system; -
Figure 2 is a depiction of an exemplary integrated system for capturing sulfur oxides and carbon dioxide from a flue gas stream; -
Figure 3 is a depiction of another exemplary integrated system for capturing sulfur oxides and carbon dioxide from a flue gas stream; and -
Figure 4 is a depiction of another exemplary integrated system for capturing sulfur oxides and carbon dioxide from a flue gas stream. - Disclosed herein is a system and a method for facilitating the integration of a desulfurization process based on a sodium reagent with the chilled ammonia process. The method comprises discharging a flue gas from a combustion process (such as from a coal combustion furnace) to a desulfurization chamber where sulfur oxides (SOx) is removed in the form of a sulfate salt. The flue gases now devoid of the sulfur oxides (or with a reduced sulfur oxide content as compared with the incoming flue gas stream) are then discharged to a carbon capture system where the carbon dioxide present in the flue gas stream is removed in the form of a carbonate salt and/or a bicarbonate salt. The carbonate salt and/or the bicarbonate salt is then decomposed to release carbon dioxide. The carbon dioxide is eventually sequestered while the flue gas now devoid of carbon dioxide and sulfur oxides (SOx) is released to the atmosphere via a stack.
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Figure 1 represents an exemplary diagram that depicts a chilled ammonia carbondioxide capture system 10 for the removal of carbon dioxide from a flue gas stream. It should be noted that the process shown inFigure 1 is only a high level overview of the Chilled Ammonia Process (CAP) and not all details associated with the CAP process are shown. - The
system 10 comprises a direct contact cooling vessel (DCC) 4, a direct contact heating vessel (DCH) 6, a water wash station 8, anabsorber 12 and aregenerator 14. A flue gas stream containing carbon dioxide that emanates from a combustion process (e.g., a boiler) is charged to a direct contact cooling vessel 4 prior to being charged to theabsorber 12. - The direct contact cooling vessel 4 reduces temperature of the incoming flue gas stream and removes residual acidic gases such as SOx and particulate matter. The flue gas stream is then charged to the
absorber 12 where carbon dioxide is removed using an absorbent solution (also referred to herein as an ammoniated solution or an ammoniated slurry). The absorption of the acidic components such as carbon dioxide present in the flue gas stream is achieved when theabsorber 12 is operated at a low temperature, for example, between zero and thirty degrees Celsius (0 to 30°C). In another example, absorption of the acidic component from flue gas stream is achieved when the absorber is operated at a temperature between zero and ten degrees Celsius (0 to 10°C). By operating at relatively low temperatures, ammonia loss within thesystem 10 is minimized. - By way of example in the
absorber 12, the ammonia reacts with the carbon dioxide present in the flue gas to form ammonium carbonate, ammonium bicarbonate, ammonium carbamate (also referred to as a carbon dioxide rich ammonia solution). The carbon dioxide rich ammonia solution is charged to theregenerator 14 where it is heated to release the carbon dioxide thereby resulting in a carbon dioxide lean ammonia solution. The carbon dioxide is subsequently cleaned and sequestered or stored for further utilization. The carbon dioxide lean ammonia solution is recycled back to theabsorber 12, where it recaptures additional carbon dioxide in a sequential portion of the flue gas stream. - In one method of functioning of the chilled ammonia process, the flue gas stream from a boiler enters the direct contact cooling vessel 4 to have its temperature reduced and to have residual acidic gases removed from it. The direct contact cooling vessel 4 uses ambient air or cooling water to lower the recirculation liquid temperature. Flue gas enters the direct contact cooling vessel 4 inlet at the bottom and flows upward through the packing (not shown). Cool water is sprayed at the top of the packing and flows downward, counter to the flue gas flow. As the gas flows upward through direct contact cooling vessel 4, it is forced into contact with the water. Direct cooling of the saturated flue gas results in the condensation of most of the water in the flue gas stream. In addition, the residual acidic gases (e.g., SO2, SO3, SOx, hydrogen chloride, and hydrogen fluoride gas) and particulates present in the flue gas are removed in the direct contact cooling vessel 4. In particular, the sulfur dioxide (SO2) is captured by the ammonia to produce ammonium sulfate.
- The flue gases leave the direct contact cooling vessel 4 and are charged to the
absorber 12. - The
absorber 12 employs an absorbent solution (disposed therein) or a slurry that facilitates the absorption and the removal of a gaseous component such as carbon dioxide from the flue gas stream. In the chilled ammonia process, the absorbent solution used in the absorber is a solution or slurry including ammonia (referred to above as an ammoniated solution or slurry). The ammonia can be in the form of an ammonium ion (NH4 +), ammonium carbamate, ammonium bicarbonate, or in the form of dissolved molecular ammonia (NH3). By way of example, the absorbent solution or slurry may be comprised of ammonium carbonate, carbamate and bicarbonate ions. As the flue gas flows upwards through theabsorber 12, it is contacted with the scrubbing slurry solution containing dissolved ammonium carbonate and ammonium bicarbonate suspended solids that flow in a countercurrent direction to the flue gas, and the CO2 is absorbed. - The flue gas exits the water wash column and enters the direct contact heating vessel 6 for removal of residual ammonia where it is captured by sulfuric acid to form ammonium sulfate before entering the chimney as clean combustion gas. The flue gas exits the
carbon dioxide absorber 12 and enters a water wash station 8 to reduce the ammonia vapor from the flue gas. In the water wash station 8, ammonia is removed using chilled water.. - The water wash station 8 is a packed column that utilizes water to absorb ammonia from the flue gas. The temperature of the flue gas is maintained using heat exchangers and a mechanical chilling system. The ammoniated water is sent to a stripper column (not shown) (CO2/NH3 stripper) where the ammonia is stripped and returned to the process as reagent. The clean water from the CO2/NH3 stripper is re-used within the water wash column to remove additional ammonia. Energy for the CO2/NH3 stripping column is provided by steam from the power generation facility.
- The ammoniated solution or ammoniated slurry (now rich in carbon dioxide in the form of ammonium carbonate or ammonium bicarbonate) is charged to a
regenerator 14 where it is heated to decompose it thereby producing carbon dioxide and the absorbent solution. The absorbent solution is returned to theabsorber 12 to contact additional flue gas and to absorb carbon dioxide from it. The remainder of the flue gas stream (now substantially devoid of carbon dioxide) is then charged to a water wash station 8 to remove ammonia from it. - The
regenerator 14 is a stripper column that contains a mass transfer process. The feed to theregenerator 14 is introduced at several stages. The carbon dioxide rich ammonia solution is flashed by heat introduced in the regenerator reboiler. Flashed carbon dioxide in the feed proceeds up the column to the overhead. As the rich solution falls through the lower regenerator bed, carbon dioxide is separated and rises to the regenerator overhead, and the solution becomes leaner as it reaches the bottom of the column. The lean solution is then returned to theabsorber 12 for re-use. - The carbon dioxide exits the top of the regeneration column and flows to a receiver at the top of the regenerator to condense residual moisture and ammonia. At these conditions, there is a significant difference in the vapor pressure between carbon dioxide and ammonia and water. Because of this difference, a very low concentration of water vapor and ammonia are present in the regenerator overhead. The carbon dioxide product stream enters the carbon dioxide compressor, which compresses the stream to a pressure of 1500 psia (103 bar) or as required by the end user.
- Disclosed herein too is an integrated system for removing sulfur oxides (SOx) and carbon dioxide from a flue gas stream. The integrated system comprises a desulfurization system that may comprise either a wet flue gas desulfurization (WFGD) system and/or a dry flue gas desulfurization system (DFGD) to remove sulfur oxides (SOx) and a carbon capture system (CCS) that captures carbon dioxide from the flue gas stream. The desulfurization system comprises a desulfurization chamber where a carbonate or bicarbonate salt is used to capture SOx from the flue gas stream and gets converted to a sulfate salt in the process. The flue gas stream now substantially devoid of sulfur oxides is charged to the carbon capture system where the carbon dioxides are captured.
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Figures 2 - 4 depict embodiments ofintegrated systems 100 that may be used for removing both sulfur oxides and carbon dioxide from a flue gas stream. The systems ofFigures 2 - 4 employ a number of common processes, as described herein. - Flue gas from a combustion process is discharged to an air-
preheater 102 that is in fluid communication with adesulfurization chamber 116 via a bag-house 104. - The bag-
house 104 facilitates the removal of particulate matter (e.g., fly ash particles and the like) prior to the flue gases entering thedesulfurization chamber 106. - A spray drier 114 disposed in parallel with the air-
preheater 102 is used to dry a small amount of purge material taken out of thedesulfurization chamber 106 as a part of zero liquid discharge from the process. - The
desulfurization chamber 106 may be a wet gas desulfurization chamber or a dry gas desulfurization chamber. A variety of different salts may be used in thedesulfurization chamber 106 to remove sulfur oxides (SOx) from the flue gas stream. Preferred salts for use in thedesulfurization chamber 106 are carbonates, bicarbonates, oxides and/or hydroxides of metals of Group IA and IIA. These include alkali metals and alkaline earth metals. Examples of suitable salts for use in the desulfurization chamber are salts such as sodium bicarbonate, potassium bicarbonate, calcium carbonate, calcium oxide, calcium hydroxide, magnesium carbonate, strontium carbonate, and the like. A preferred bicarbonate salt for use in thedesulfurization chamber 106 is sodium bicarbonate. - When calcium oxide and/or calcium hydroxides are used for desulfurization of the flue gases, the desulfurization chamber is preferably a wet gas desulfurization chamber.
- The resulting salts produced in the
desulfurization chamber 106 as a result of the reaction with the sulfur oxides (SOx from the flue gas stream) are sulfates of alkali metals and alkaline earth metals. Exemplary sulfates are sodium sulfate, potassium sulfate, calcium sulfate, magnesium sulfate, strontium sulfate, and the like - A flue gas stream (from the combustion process) along with a stream of air is introduced into the
desulfurization chamber 106. The air provides the oxygen that is used to convert the sulfite salt to a sulfate salt. A bicarbonate salt is also introduced into thechamber 106 from the product reactor andseparator 110. - In the
desulfurization chamber 106, the bicarbonate salt reacts with the sulfur oxides present in the flue gas stream to form a sulfate salt. For sodium bicarbonate, the reaction (2) is as follows.
2NaHCO3 + SO2 + ½O2 → Na2SO4 + H2O + 2CO2 (2)
The sulfate salt (e.g., sodium sulfate) is then charged to the product reactor andseparator 110. An exemplary salt is sodium sulfate. - While the chilled ammonia process comprises a number of different components (such as an absorber, a regenerator, a direct contact cooling vessel, a direct contact heating vessel, a water wash station and a CO2 wash as shown in the
Figure 1 )Figures 2 through 4 represent the entire chilled ammonia process byreference numeral 108. - In the
chilled ammonia process 108, carbon dioxide is absorbed from the flue gas stream by an absorbent present in an absorber (not shown). The absorbent with the carbon dioxide dissolved therein (termed a carbon dioxide-rich solution) is then discharged from the absorber to a regenerator where the carbon dioxide is separated from the absorbent to form a carbon-dioxide-rich stream and a carbon dioxide-lean stream. - The carbon dioxide-rich stream is then sequestered or utilized.
- The absorbent now devoid of carbon dioxide (termed a carbon dioxide lean ammonia solution) is recycled back to the absorber to absorb additional carbon dioxide from the incoming flue gas stream.
- Details of the chilled ammonia process are discussed above and as well as detailed in several patents namely
U.S. Patent No. 8,690,992B2 to Dube et al. , andUS 7,862,788 to Gal et al. , the entire contents of which are hereby incorporated by reference. - The product reactor and
separator 110 receives ammonium bicarbonate from the chilledammonia process 108 and reacts it with the sulfate salt to produce ammonium sulfate and the bicarbonate salt. This reaction for sodium sulfate is detailed as shown in reaction (1) above and is reproduced again below.
Na2SO4 + 2NH4HCO3 → 2NaHCO3 + (NH4)2SO4 (1)
The reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution. - The sodium bicarbonate is recycled to the
desulfurization chamber 106 while the ammonium sulfate is discharged to the bipolar membrane electrodialysis and then decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process. - The ammonia is used as a reagent make-up required in the CO2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere.
- The bipolar
membrane electrodialysis device 112 facilitates the decomposition of ammonium sulfate into sulfuric acid and ammonia. The ammonia is charged to thechilled ammonia device 108 and is recycled to the absorber (seeFigure 1 ) where it absorbs carbon dioxide to form ammonium carbonate/bicarbonate solution. A portion of the sulfuric acid is also charged to the chilledammonia process 108 where it is used in the DCH () to convert ammonia slip to ammonium sulfate. The remaining sulfuric acid may be used for other commercial purposes. The ammonium sulfate obtained from the DCC/DCH is fed back to theelectrodialysis device 112, where it is decomposed to ammonia and to sulfuric acid in a manner similar to the ammonium sulfate received from the product reactor andseparator 110. Any water obtained from the decomposition of ammonium sulfate and any non-decomposed ammonium sulfate produced in theelectrodialysis device 112 is returned to the product reactor andseparator 110. - The bipolar
membrane electrodialysis device 112 generally includes an anion exchange membrane and a cation exchange membrane physically or chemically bonded together. Under the driving force of an electrical field, the bipolar membrane dissociates water into hydrogen and hydroxyl ions. - There are substantial advantages to water splitting with the bipolar membrane. Since there are no gases evolved at the surface or within the bipolar membranes, the energy associated with conversion of oxygen and hydrogen is saved. The ions generated in the electro dialysis device pass though anion and cation exchange perm-selective membranes to react with the aqueous alkali and/or alkaline earth metal sulfur salt solution to produce the corresponding acid (e.g., sulfuric acid, sulfurous acid) and a regenerated ammonia feed stream. The acid containing feed stream can then be circulated to the chilled ammonia device along with the ammonia. This method advantageously reduces the operating cost of CAP significantly.
- Additionally, the electrodialysis device eliminates the need for the end user to handle the byproduct stream that would typically be generated using an ammonia solution (i.e., the ammonium sulfate), which will further enhance the efficiency of the chilled ammonia process. Details of the functioning of the bipolar
membrane electrodialysis device 112 are disclosed inU.S. Patent Publication No. 20130064748 A1 to Dube , the entire contents of which are hereby incorporated by reference. - Flue gas containing residual SOx is directed from the
desulfurization chamber 106 to the directcontact cooling vessel 118. The directcontact cooling vessel 118 lies downstream of thedesulfurization chamber 116. The directcontact cooling vessel 118 lies upstream of the product reactor andseparator 110. - In the direct
contact cooling vessel 118, sodium hydroxide solution is charged to the top of the vessel while the flu gas containing residual SOx is charged to the bottom of the reactor. The flue gas travels from the bottom upwards counter current to the flow of the sodium hydroxide solution. The SOx present in the flue gas stream is absorbed by the sodium hydroxide to form sodium sulfate which is charged to the product reactor andseparator 110. The flue gas (now devoid of SOx) is charged to thecarbon capture system 108. Gypsum from the directcontact cooling vessel 118 is fed to thedesulfurization chamber 106. - In
Figure 2 , the product reactor andseparator 110 is fed with lime to convert the sodium sulfate to gypsum, which is charged to the wet fluegas desulfurization chamber 106. The sodium sulfate produced in directcontact cooling vessel 118 is charged to the product reactor andseparator 110 to produce gypsum and sodium hydroxide. The gypsum is recycled to the wet fluegas desulfurization chamber 106. Sodium hydroxide produced in the product reactor andseparator 110 as a result of the reaction between the lime and the sodium sulfate is recycled to the directcontact cooling vessel 118. - As shown in the
Figure 2 , the carbon dioxide obtained from thecarbon capture system 108 can then be sequestered or utilized. The system of theFigure 2 thus integrates desulfurization of the flue gas stream with carbon dioxide removal. The lime and/or limestone present in the wet fluegas desulfurization chamber 106 reacts with the sulfur oxides (SOx) in the flue gas stream to produce gypsum (CaSO4.2H2O). The gypsum may be removed from the fluegas desulfurization chamber 116 and replaced with additional lime and/or limestone to facilitate the further removal of sulfur oxides from the flue gas stream. -
Figure 3 is a depiction of another exemplaryintegrated system 100 that combines desulfurization with the chilled ammonia process to remove sulfur oxides and carbon dioxide from the flue gas stream. - As seen in the
Figure 3 , a product reactor andseparator 110 is used to facilitate the reaction between the sodium sulfate salt (from the desulfurization chamber 106) and ammonium bicarbonate (from the chilled ammonia process 108). This reaction is detailed below in (1):
Na2SO4 + 2NH4HCO3 → 2NaHCO3 + (NH4)2SO4 (1)
- The reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution. The sodium bicarbonate is recycled to the desulfurization chamber while the ammonium sulfate is decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process. The ammonia is used as a reagent make-up required in the CO2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere. This is discussed in detail in the sections directed to the product reactor and
separator 110 and thedesulfurization chamber 106. - As noted above, the reaction produces a sodium bicarbonate salt and ammonium sulfate solution. A sodium bicarbonate salt is precipitated and separated from the mixture and ammonium sulfate solution is sent to a bipolar membrane electrodialysis unit. A bipolar
membrane electrodialysis unit 112 is used to decompose the ammonium sulfate to ammonia & sulfuric acid which is fed back to the chilled ammonia process. Sulfuric acid is removed from the bipolarmembrane electrodialysis unit 112 and a portion of it is fed to the chilled ammonia process. - From the
Figure 3 , it may be seen that the product reactor andseparator 110 lies in a cyclical loop with the chilledammonia process 108 and thedesulfurization chamber 106. In this loop, flue gases (now devoid of sulfur oxides) from thedesulfurization chamber 106 are charged to the absorber (not shown) of the chilledammonia process 108. A small portion of the ammonium bicarbonate from the absorber is then discharged from the absorber to the product reactor andseparator 110, where it reacts with the sulfate salt to produce a bicarbonate salt, which is charged to thedesulfurization chamber 106. - There also exists a recycle loop between the
desulfurization chamber 106 and the product reactor andseparator 110. The sulfate salt from thedesulfurization chamber 106 is charged to the product reactor andseparator 110 and the bicarbonate salt from the product reactor andseparator 110 is charged to thedesulfurization chamber 106. - A number of recycle loops also exist between the product reactor and
separator 110, the bipolarmembrane electrodialysis unit 112 and thechilled ammonia process 108. In one recycle loop, ammonium sulfate from the product reactor andseparator 110 is charged to the bipolarmembrane electrodialysis unit 112 while water and unreacted ammonium sulfate are recycled back to the product reactor andseparator 110 from the bipolarmembrane electrodialysis unit 112. - Another recycle loop exists between the
chilled ammonia process 108 and the bipolarmembrane electrodialysis unit 112 where ammonium sulfate from the chilledammonia process 108 is fed to the bipolarmembrane electrodialysis unit 112 and where ammonia and sulfuric acid produced in the bipolarmembrane electrodialysis unit 112 are recycled to the chilledammonia process 108. - In one embodiment, in one manner of using the
system 100 of theFigure 3 , the sodium bicarbonate reacts with sulfur oxides present in the flue gas stream in thedesulfurization chamber 106 to produce sodium sulfate. The sodium sulfate is charged to the product reactor andseparator 110 where a portion of ammonium bicarbonate is received from the absorber (not shown) of the chilledammonia process 108. The reaction between sodium sulfate and ammonium bicarbonate results in the formation of ammonium sulfate and sodium bicarbonate. The sodium bicarbonate is recycled to thedesulfurization chamber 106 where it reacts with incoming sulfur oxides in the flue gas stream. The sodium bicarbonate is thus charged from the product reactor andseparator 110 to thedesulfurization chamber 106 while sodium sulfate is charged from thedesulfurization chamber 106 to product reactor andseparator 110. - The bipolar
membrane electrodialysis device 112 receives the ammonium sulfate from the product reactor andseparator 110 and decomposes it to ammonia and sulfuric acid. The ammonia is charged to the absorber of the chilledammonia process 108 where it forms ammonium bicarbonate. A portion of sulfuric acid generated in the bipolarmembrane electrodialysis device 112 is charged to the chilledammonia process 108 where it reacts with the ammonia slip in the DCH to produce ammonium sulfate. This ammonium sulfate is charged to the bipolarmembrane electrodialysis device 112 from the chilledammonia process 108 where it is decomposed to form ammonia and sulfuric acid. Any water or unused ammonium sulfate from the bipolarmembrane electrodialysis device 112 are discharged to the product reactor andseparator 110. - In an embodiment, a portion of sodium bicarbonate may be diverted from being charged to the desulfurization chamber 106 (from the product reactor and separator 110) to
points air preheater 102 where it can be used to absorb a small portion of sulfur oxides (SOx) from the incoming flue gas stream Atpoints desulfurization chamber 106 and hence the removal of sulfur oxides (especially SO3) from the flue gas stream is more efficient. - In another embodiment, a
small purge stream 105 is charged from thedesulfurization chamber 106 to thespray dryer 114 where heat from the flue gas stream is used to dry the contents of the purge stream. - The
Figure 4 depicts another embodiment of the exemplaryintegrated system 100 that combines sulfur oxide removal with carbon dioxide removal from a flue gas stream once again with the use of the chilled ammonia process. - In the embodiment depicted in the
Figure 4 , thesystem 100 comprises a wet flue gas desulfurization and/or a dry flue gas desulfurization chamber 116 (hereinafter and a directcontact cooling vessel 118 in addition to the components contained in thesystem 100 depicted in theFigure 3 ). - In this embodiment, the flue
gas desulfurization chamber 106 of theFigure 3 is replaced with a wet fluegas desulfurization chamber 106 that contains lime (CaO or Ca(OH)2) or limestone (CaCO3). The wet fluegas desulfurization chamber 106 lies upstream of a directcontact cooling vessel 118. - Wet flue gas desulfurization systems are detailed in
U.S. Patent Publication No. 2013/0064748 , the entire contents of which are hereby incorporated by reference. The flue gas exiting the flue gas desulfurization unit is typically at a temperature of about 50 to 60°C for wet flue gas desulfurization systems and about 80 to 100°C for dry flue gas desulfurization systems (see thedesulfurization chamber 106 of theFigure 3 ). The gas is water saturated for systems that employ wet flue gas desulfurization systems whereas for systems with upstream dry flue gas desulfurization, the gas has temperature that is approximately 20 to 40°F above moisture saturation and each gas stream typically contains residual contaminants including SOx, among others. In order to cool the saturated gas, both sensible heat and latent heat for water vapor condensation has to be removed. To accomplish this, the flue gas is fed to a direct contact cooling tower vessel (DCC) 118 to reduce the temperature of the flue gas and to further remove contaminants such as SOx. - The remaining flue gas from the wet flue
gas desulfurization chamber 116 is then charged to the directcontact cooling vessel 118 where any residual sulfur oxides are removed. The directcontact cooling vessel 118 may be a packed tower with liquid recirculation through a cooling tower having multiple stages that uses ambient air to lower the recirculation liquid temperature. An alkali and/or alkaline earth metal hydroxide reagent such as sodium hydroxide is introduced into a first stage of the directcontact cooling vessel 118 and mixed with cooling water at a bottom portion of the directcontact cooling vessel 118. Details of the operation of the directcontact cooling vessel 118 are provided inU.S. Patent Publication No. 2013/0064748 , the entire contents of which are hereby incorporated by reference. - In an embodiment, the aqueous alkali and/or alkaline earth metal hydroxide solution is pumped via pump (not shown) through a conduit (not shown) to a top portion of the direct
contact cooling vessel 118. Optionally, the aqueous alkali and/or alkaline earth metal hydroxide solution may first be pumped to a chiller (not shown) to further lower the temperature of the aqueous alkali and/or alkaline earth metal hydroxide solution. Flue gas enters the directcontact cooling vessel 118 inlet at the bottom portion and flows upward. - The cool aqueous alkali and/or alkaline earth metal hydroxide solution is sprayed at the top of the packing and flows downwards, counter to the flue gas flow. As the flue gas flows upwards through direct
contact cooling vessel 118, the flue gas is forced into contact with the aqueous alkali and/or alkaline earth metal hydroxide solution. Direct cooling of the saturated flue gas in subsequent stages results in the condensation of most of the water in the flue gas stream. In addition to reaction of SOx, the residual gases present in the flue gas are generally rendered water soluble. Moreover, any SOx contaminants entrained in the flue gas react with the aqueous alkali and/or alkaline earth metal hydroxide solution to form a feed-stream of the corresponding aqueous alkali and/or alkaline earth metal sulfur containing salt solution. - In an embodiment, when sodium hydroxide is used as the hydroxide solution in the direct
contact cooling vessel 118, it absorbs the sulfur oxides to produce sodium sulfate. The sodium sulfate from the directcontact cooling vessel 118 is then discharged to the product reactor andseparator 110 where it reacts with ammonium bicarbonate to produce ammonium sulfate and sodium bicarbonate as detailed in theFigure 3 above. The flue gas stream now substantially devoid of SOx is charged to the chilledammonia process 108 viastream 107. The remainder of the system of theFigure 4 functions as detailed above with reference to theFigure 3 and will not be detailed again in the interests of brevity. - The system of the
Figure 4 is useful in that it is useful for retrofitting existing systems that have carbon capture processes already installed based on Chilled Ammonia process. They are useful where regulations for the desulfurization system are not stringent - It will be understood that when an element or layer is referred to as being "on," "interposed," "disposed," or "between" another element or layer, it can be directly on, interposed, disposed, or between the other element or layer or intervening elements or layers may be present.
- It will be understood that, although the terms first, second, third, and the like may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another element, component, region, layer or section. Thus, first element, component, region, layer or section discussed below could be termed second element, component, region, layer or section without departing from the teachings of the present invention.
- As used herein, the singular forms "a," "an" and "the" are intended to comprise the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms "comprises" and/or "comprising," when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
- Unless otherwise defined, all terms (including technical and scientific terms) used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. It will be further understood that terms, such as those defined in commonly used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the relevant art and will not be interpreted in an idealized or overly formal sense unless expressly so defined herein.
- Furthermore, in describing the arrangement of components in embodiments of the present disclosure, the terms "upstream" and "downstream" are used. These terms have their ordinary meaning. For example, an "upstream" device as used herein refers to a device producing a fluid output stream that is fed to a "downstream" device. Moreover, the "downstream" device is the device receiving the output from the "upstream" device. However, it will be apparent to those skilled in the art that a device may be both "upstream" and "downstream" of the same device in certain configurations, e.g., a system comprising a recycle loop.
- Various aspects and embodiments of the present invention are defined by the following clauses:
- 1. An integrated system for capturing carbon dioxide and sulfur oxides from a flue gas stream comprising:
- a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; where the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt is used to absorb sulfur oxides from the flue gas stream to form a metal sulfate; and
- a carbon capture system in fluid communication with the desulfurization chamber; where the carbon capture system is operative to absorb carbon dioxide from the flue gas stream.
- 2. The integrated system of Clause 1, where the system comprises a chilled ammonia process.
- 3. The integrated system of Clause 2, further comprising a product reactor and separator where the metal sulfate is reacted with a bicarbonate salt from the chilled ammonia process.
- 4. The integrated system of Clause 3, where the bicarbonate salt is ammonium bicarbonate.
- 5. The integrated system of Clause 4, further comprising a bipolar membrane electrodialysis unit that receives ammonium sulfate from the product reactor and separator and dissociates it into ammonia and sulfuric acid.
- 6. The integrated system of Clause 5, where the ammonia is fed to an absorber in the chilled ammonia process and where the sulfuric acid is fed to a direct contact heating vessel to treat the ammonia slip.
- 7. The integrated system of Clause 1, where the desulfurization chamber can be a wet flue gas desulfurization system or a dry flue gas desulfurization system.
- 8. The integrated system of Clause 7, where the wet flue gas desulfurization system uses lime or limestone, sodium carbonate, sodium bicarbonate, sodium hydroxide, or a combination thereof to capture sulfur oxides from the flue gas stream.
- 9. The integrated system of Clause 8, further comprising a direct contact cooling vessel that receives a flue gas stream from the wet flue gas desulfurization system, where the direct contact cooling vessel is operative to remove sulfur oxides from the flue gas stream and transport the flue gas stream now substantially devoid of sulfur oxides to the chilled ammonia process.
- 10. The integrated system of Clause 7, where the dry flue gas desulfurization system uses sodium bicarbonate to capture sulfur oxides from the flue gas stream.
- 11. The integrated system of
Clause 10, where the sodium bicarbonate is converted to sodium sulfate in the dry flue gas desulfurization system and where sodium bicarbonate produced in a product reactor and separator is charged to the dry flue gas desulfurization system. - 12. The integrated system of Clause 2, further comprising a product reactor and separator where the metal sulfate is reacted with lime to produce a metal hydroxide that is charged to a direct contact cooling vessel; where the metal hydroxide captures sulfur oxides from the incoming flue gas stream.
- 13. The integrated system of Clause 1, where a portion of the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt contacts the flue gas stream at points upstream or downstream of an air preheater.
- 14. A method comprising:
- charging a flue gas stream produced in a combustion process to an integrated system for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system comprises:
- removing SOx particulates in a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal to provide a SOx-lean flue gas; and
- providing the SOx-lean flue gas to a carbon capture system in fluid communication with the desulfurization chamber;
- absorbing sulfur oxides from the flue gas stream in the desulfurization chamber; and
- absorbing carbon dioxide from the flue gas stream in the carbon capture system.
- charging a flue gas stream produced in a combustion process to an integrated system for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system comprises:
- 15. The method of
Clause 14, further comprising converting the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt into a metal sulfate salt in the desulfurization chamber. - 16. The method of Clause 15, further comprising reacting the metal sulfate salt with ammonium bicarbonate produced in the carbon capture system to produce a metal bicarbonate and ammonium sulfate.
- 17. The method of Clause 16, further comprising charging the ammonium sulfate to a electrodialysis unit.
- 18. The method of Clause 17, further comprising charging ammonia from the electrodialysis unit to the carbon capture system and charging sulfuric acid from the electrodialysis unit to a water wash system to react with the ammonia slip.
- 19. The method of Clause 18, further comprising charging ammonium sulfate from the DCH is charged to the electrodialysis unit.
Claims (15)
- An integrated system (100) for capturing carbon dioxide and sulfur oxides from a flue gas stream comprising:a desulfurization chamber (106,116) comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; where the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt is used to absorb sulfur oxides from the flue gas stream to form a metal sulfate; anda carbon capture system (108) in fluid communication with the desulfurization chamber (106,116); where the carbon capture system (108) is operative to absorb carbon dioxide from the flue gas stream.
- The integrated system (100) of Claim 1, where the system comprises a chilled ammonia process (108).
- The integrated system (100) of Claim 2, further comprising a product reactor and separator (110) where the metal sulfate is reacted with a bicarbonate salt from the chilled ammonia process (108).
- The integrated system (100) of Claim 3, where the bicarbonate salt is ammonium bicarbonate.
- The integrated system (100) of Claim 4, further comprising a bipolar membrane electrodialysis unit (112) that receives ammonium sulfate from the product reactor and separator (110) and dissociates it into ammonia and sulfuric acid.
- The integrated system (100) of Claim 5, where the ammonia is fed to an absorber (12) in the chilled ammonia process (108) and where the sulfuric acid is fed to a direct contact heating vessel to treat the ammonia slip.
- The integrated system (100) of any one of Claims 1 to 6, where the desulfurization chamber (106,116) can be a wet flue gas desulfurization system or a dry flue gas desulfurization system.
- The integrated system (100) of Claim 7, where the wet flue gas desulfurization system uses lime or limestone, sodium carbonate, sodium bicarbonate, sodium hydroxide, or a combination thereof to capture sulfur oxides from the flue gas stream.
- The integrated system (100) of Claim 7 or 8, further comprising a direct contact cooling vessel (4, 118) that receives a flue gas stream from the wet flue gas desulfurization system, where the direct contact cooling vessel (4, 118) is operative to remove sulfur oxides from the flue gas stream and transport the flue gas stream now substantially devoid of sulfur oxides to the chilled ammonia process (108).
- The integrated system (100) of Claim 7 or 9, where the dry flue gas desulfurization system uses sodium bicarbonate to capture sulfur oxides from the flue gas stream.
- The integrated system (100) of Claim 2, further comprising a product reactor and separator (110) where the metal sulfate is reacted with lime to produce a metal hydroxide that is charged to a direct contact cooling vessel (4, 118); where the metal hydroxide captures sulfur oxides from the incoming flue gas stream.
- The integrated system (100) of any one of Claims 1 to 11, where a portion of the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt contacts the flue gas stream at points upstream or downstream of an air preheater (102).
- A method comprising:charging a flue gas stream produced in a combustion process to an integrated system (100) for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system (100) comprises:removing SOx particulates in a desulfurization chamber (106,116) comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal to provide a SOx-lean flue gas; andproviding the SOx-lean flue gas to a carbon capture system (108) in fluid communication with the desulfurization chamber (106,116);absorbing sulfur oxides from the flue gas stream in the desulfurization chamber (106,116); andabsorbing carbon dioxide from the flue gas stream in the carbon capture system (108).
- The method of Claim 13, further comprising converting the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt into a metal sulfate salt in the desulfurization chamber (106,116).
- The method of Claim 14, further comprising reacting the metal sulfate salt with ammonium bicarbonate produced in the carbon capture system (108) to produce a metal bicarbonate and ammonium sulfate.
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US15/180,781 US20170354926A1 (en) | 2016-06-13 | 2016-06-13 | Integrated desulfurization and carbon dioxide capture system for flue gases |
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EP3257570B1 EP3257570B1 (en) | 2019-03-20 |
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CN113041812A (en) * | 2021-03-16 | 2021-06-29 | 河北工业大学 | Device and method for coupling seawater decalcification and flue gas carbon fixation desulfurization and denitrification |
US20220357242A1 (en) * | 2021-05-07 | 2022-11-10 | Entegris, Inc. | Multistage gas sampling trap and detection of sulfurous species contaminant |
WO2023147101A1 (en) * | 2022-01-31 | 2023-08-03 | Michigan Technological University | Reduced reagent regeneration energy for carbon dioxide capture with bipolar membrane electrodialysis, systems and related methods |
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WO2009056830A1 (en) * | 2007-11-01 | 2009-05-07 | Alstom Technology Ltd | Carbon capture system and process |
US7862788B2 (en) | 2007-12-05 | 2011-01-04 | Alstom Technology Ltd | Promoter enhanced chilled ammonia based system and method for removal of CO2 from flue gas stream |
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